Northern Oil and Gas, Inc. — Form 10-Q Summary
Reporting period: Quarter and nine months ended September 30, 2019. The company is a non-operated oil and gas producer focused on the Bakken and Three Forks formations in the Williston Basin, North Dakota and Montana.
Financial and operating results
| Metric | Q3 2019 | Q3 2018 | Nine months 2019 | Nine months 2018 |
|---|---|---|---|---|
| Oil and gas sales | $158.0 million | $145.4 million | $440.5 million | $341.3 million |
| Total revenue, including derivative gains and losses | $233.9 million | $102.3 million | $413.4 million | $235.7 million |
| Income (loss) from operations | $121.1 million | $35.6 million | $118.0 million | $77.8 million |
| Net income (loss) | $94.4 million | $19.0 million | $31.6 million | $(74.6) million |
| Diluted earnings (loss) per share | $0.24 | $0.06 | $0.08 | $(0.40) |
| Operating cash flow | Not provided separately | Not provided separately | $269.3 million | $126.4 million |
- Q3 production was 3.75 million Boe, or about 40,786 Boe per day, up 53% year over year; oil represented about 80% of production. Nine-month production increased 68% to 10.05 million Boe.
- Q3 oil and gas sales excluding settled derivatives increased 9%, as higher production more than offset lower realized prices. Realized oil price after settled derivatives was $57.02/Bbl, down 4%; realized price including all derivative settlements was $47.00/Boe, down 13%.
- Derivative results materially affected reported revenue and earnings: Q3 net gain was $75.9 million, including a $57.5 million noncash mark-to-market gain. For nine months, the net derivative loss was $27.1 million, including a $62.8 million noncash mark-to-market loss. Derivatives are not designated for hedge accounting.
- Q3 production expense was $8.62/Boe, up from $7.39; DD&A was $14.81/Boe, up from $12.31, with the company citing acquisitions and production growth. Nine-month production expense was $8.27/Boe and DD&A was $14.61/Boe.
- Nine-month investing cash use was $417.9 million, including $206.3 million of drilling and development spending and $210.6 million for property acquisitions. Financing provided $148.2 million, primarily from net revolver borrowings.
Balance sheet, liquidity and capital
- At September 30, cash was $1.9 million and working capital was negative $58.7 million, compared with a $3.1 million deficit at December 31, 2018. Current assets included $105.2 million of net derivative assets.
- Long-term debt carrying value was $1.14 billion; principal comprised $688.5 million of 8.5% second-lien notes due 2023, $327.0 million drawn on the revolving facility, and a $130.0 million unsecured 6% VEN Bakken note. Revolver availability was $98.0 million against a $425.0 million borrowing base; reported total liquidity was $99.9 million.
- Management said operating cash flow, cash on hand and revolver capacity should fund budgeted capital expenditures and operating needs for at least the next 12 months. The company reported operating cash flow exceeded drilling and development cash spending by $63.0 million for the first nine months, excluding acquisitions, and expected future cash flow surplus excluding acquisitions.
- Stockholders’ equity was $514.1 million. Common shares outstanding at September 30 were 404.3 million; 405.8 million were outstanding as of November 8.
Material changes and notable items
- The July 1 VEN Bakken acquisition added approximately 90.1 net producing wells, 3.3 net wells in process and 18,000 net acres. Consideration was estimated at $312.4 million: $172.1 million cash, 5.6 million shares valued at $11.7 million, and a $130.0 million note. The acquired assets contributed about 6,949 Boe/d, or 17% of Q3 average production.
- Q3 total revenue rose 129% and nine-month revenue rose 75%, reflecting production growth and substantially different derivative results versus the prior periods. Nine-month oil sales increased 32%, while natural gas and NGL sales declined 7%.
- Capitalized oil and gas properties included $178.8 million in accounts payable and accrued liabilities at quarter-end, reflecting development activity. The filing reports $619.3 million of capitalized property costs incurred in the first nine months versus $416.9 million of related cash spending.
- On November 8, 2019, the company amended its revolving credit covenants. The maximum total-net-debt-to-EBITDAX ratio became 3.75 to 1.00; minimum current-ratio thresholds were reset to 0.85 at September 30, 0.65 at December 31, 2019, 0.90 at March 31, 2020, and 1.00 thereafter.
Outlook, risks and contingencies
- No specific production, earnings or capital-spending guidance is provided in the supplied filing text. Management’s liquidity outlook is conditional on operating cash flow and borrowing availability; capital spending may be reduced if cash flows weaken.
- Key exposures include volatile oil prices, Williston Basin price differentials, weather and infrastructure constraints, operator drilling and completion decisions, acquisition execution, and access to capital. Q3 oil differential to NYMEX was $5.48/Bbl versus $4.16/Bbl a year earlier; curtailments, shut-ins and completion delays constrained production.
- At September 30, open oil swaps covered 19.0 million barrels at a weighted average price of approximately $57.32/Bbl, across 2019–2022. Hedging can moderate downside exposure but may limit gains from rising prices; counterparties also present performance risk.
- The company recorded a $28.6 million nine-month contingent-consideration loss and an $8.0 million impairment of other current assets. A $115.9 million valuation allowance was recorded against deferred tax assets; no income tax expense or benefit was reported for the periods shown.
- An ongoing dispute over mineral ownership beneath the Missouri River within the Fort Berthold Reservation could require reversal of approximately $4.8 million of accrued revenue, net of taxes, if resolved adversely. Management believes ordinary-course legal matters will not materially affect the company, but outcomes are uncertain.
- The filing states disclosure controls were effective at September 30, 2019 and that there were no material changes in internal control over financial reporting during the quarter.
Most important facts for investors to verify
- Whether production growth and operating cash generation persist without comparable acquisition spending, and how much of reported performance is acquisition-driven.
- Current covenant compliance and liquidity following the November 8 amendment, including the reduced borrowing-base availability and working-capital deficit.
- Debt repayment and interest obligations, especially the VEN Bakken note’s required 50% principal repayment by January 1, 2021 and the remaining amount by July 1, 2022.
- Hedge volumes, realized pricing, basis differentials and exposure to future commodity-price changes; distinguish cash settlements from noncash mark-to-market earnings.
- The effect of infrastructure constraints, higher per-Boe production costs and acquisition-related depletion on margins and future production.
- Resolution of the riverbed mineral-title dispute and the valuation and settlement of contingent consideration.